1. Technical Field of the Invention
The present Invention relates to hydrocarbon well stimulation, and more particularly to methods and compositions to remove (and more generally to transfer) fluid deliberately introduced into the subsurface. For instance, the methods and compositions of the present invention involve creating then exploiting a capillary pressure gradient at the fracture face to systematically induce fluid flow from the fracture into the formation (or from the formation into the fracture), thereby increasing effective fracture length, hence, improving conductivity.
This Application is one member of a family of patent applications by Hinkel and England, the Inventors of the present Invention, and assigned to Schlumberger Technology Corporation. The common feature of these Applications is that they are all directed to transferring fluids in the subsurface by non-hydraulic means. The other Applications in this family are, Enhancing Fluid Removal From Subsurface Fractures Deliberately Introduced Into the Subsurface, U.S. patent application Ser. No. 09/087,286; and, Novel Fluids and Techniques for Maximizing Fracture Fluid Clean-up, U.S. patent application Ser. No. 09/216,420. Each of these Applications is incorporated by reference in its entirety into the present Application.
2. The Prior Art
The present Invention relates generally to hydrocarbon (petroleum and natural gas) production from wells drilled in the earth. Obviously, it is desirable to maximize both the rate of flow and the overall capacity of hydrocarbon from the subsurface formation to the surface, where it can be recovered. One set of techniques to do this is referred to as "stimulation" and one such technique, "hydraulic fracturing," is the primary, though not the exclusive subject of the present Invention.
The rate of flow or "production" of hydrocarbon from a geologic formation is naturally dependent on numerous factors. One of these factors is the radius of the borehole; as the bore radius increases, the production rate increases, everything else being equal. Another, related to the first, is the flowpaths available to the migrating hydrocarbon.
Drilling a hole in the subsurface is expensive--which limits the number of wells that can be economically drilled--and this expense only generally increases as the size of the hole increases. Additionally, a larger hole creates greater instability to the geologic formation, thus increasing the chances that the formation will shift around the wellbore and therefore damage the wellbore (and at worse collapse). So, while a larger borehole will, in theory, increase hydrocarbon production, it is impractical, and there is a significant downside. Yet, a fracture or large crack within the producing zone of the geologic formation, originating from and radiating out from the wellbore, can actually increase the "effective" (as opposed to "actual") wellbore radius, thus, the well behaves (in terms of production rate) as if the entire wellbore radius were much larger. Hence, the hydrocarbon can move from the formation into and along or within the fracture and more easily to the wellbore.
Fracturing (generally speaking, there are two types, acid fracturing and propped fracturing, the latter of primary interest here) thus refers to methods used to stimulate the production of fluids resident in the subsurface, e.g., oil, natural gas, and brines. Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation (i.e. above the minimum insitu rock stress). Morc particularly, a fluid is injected through a wellbore; the fluid exits through holes (perforations in the well casing) and is directed against the face of the formation (sometimes wells are completed openhole where no casing and therefore no perforations exist so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum insitu stress (also known as minimum principal stress) to initiate and/or extend a fracture(s) into the formation. Actually, what is created by this process is not always a single fracture, but a fracture zone, i.e., a zone having multiple fractures, or cracks in the formation, through which hydrocarbon can more easily flow to the wellbore.
In practice, fracturing a well is a highly complex operation performed with precise and exquisite orchestration of equipment, highly skilled engineers and technicians, and powerful integrated computers that monitor rates, pressures, volumes, etc. in real time. During a typical fracturing job, tens of thousands of gallons of materials are pumped into the formation at pressures high enough to actually split the formation in two, thousands of feet below the earth's surface.
A typical fracture zone is shown in context, in FIG. 1. The actual wellbore--or hole in the earth into which pipe is placed through which the hydrocarbon flows up from the hydrocarbon-bearing formation to the surface--is shown at 10, and the entire fracture zone is shown at 20. The vertical extent of the hydrocarbon-producing zone is ideally (but not generally) coextensive with the fracture-zone height (by design). These two coextensive zones are shown bounded by 22 and 24. The fracture is usually created in the producing zone of interest (rather than another geologic zone) because holes or perforations, 26-36, are deliberately created in the well casing beforehand; thus the fracturing fluid flows down (vertically) the wellbore and exits through the perforations. Again, the reservoir does not necessarily represent a singular zone in the subterranean formation, but may, rather represent multiple zones of varying dimensions.
Thus, once the well has been drilled, fractures are often deliberately introduced in the formation, as a means of stimulating production, by increasing the effective wellbore radius. Clearly then, the longer the fracture, the greater the effective wellbore radius. More precisely, wells that have been hydraulically fractured exhibit both radial flow around the wellbore (conventional) and linear flow from the hydrocarbon-bearing formation to the fracture, and further linear flow along the fracture to the wellbore. Therefore, hydraulic fracturing is a common means to stimulate hydrocarbon production in low permeability formations. In addition, fracturing has also been used to stimulate production in high permeability formations. Obviously, if fracturing is desirable in a particular instance, then it is also desirable, generally speaking, to create as large (i.e., long) a fracture zone as possible--e.g., a larger fracture means an enlarged flowpath from the hydrocarbon migrating towards the wellbore and to the surface.
Yet many wells behave as though the fracture length were much shorter because the fracture is contaminated with fracturing fluid (i.e., more particularly, the fluid used to deliver the proppant as well as a fluid used to create the fracture, both of which shall be discussed below). The most difficult portion of the fluid to recover is that retained in the fracture tip--i.e. the distant-most portion of the fracture from the wellbore. Thus, the result of stagnant fracturing fluid in the fracture naturally diminishes the recovery of hydrocarbons. The reasons for this are both simple and complex. Most simply, the presence of fluid in the fracture acts as a barrier to the migration of hydrocarbon from the formation into the fracture. More precisely, the aqueous-based fluid saturates the pore spaces of the fracture face, preventing the migration of hydrocarbon into the same pore spaces, i.e., that fluid-saturated zone has zero permeability to hydrocarbon.
Indeed, diminished effective fracture length caused by stagnant fluid retained in the fracture tip is perhaps the most significant variables limiting hydrocarbon production (both rate and capacity) from a given well. This is particularly true for low permeability reservoirs (approx. &lt;50 millidarcys). The significance of this stagnant fluid on well productivity is evidenced by the empirical observation well known to the skilled reservoir engineer that effective fracture lengths (the true fracture length minus the distal portion of the fracture saturated with fracturing fluid) are generally much less than the true hydraulically-induced fracture length. To achieve an increase in effective fracture length--so that it approaches the true fracture length--therefore involves removing stagnant fracturing fluid from the fracture particularly the tip.
The deliberate removal of fracturing fluid from the fracture is known as "clean-up," i.e., this term refers to recovering the fluid once the proppant has been delivered to the fracture. The current state-of-the-art method for fracture clean-up involves very simply, pumping or allowing the fluid to flow out of the fracture--thus the fracture fluid residing in the tip must traverse the entire length of the fracture (and up the wellbore) to be removed from the fracture. The present Application is directed in part to an improved method--and compositions to execute that method--for clean-up of the fracture.
The most difficult task related to fracture clean-up is to remove the stagnant fracture fluid retained in the fracture tip (i.e., farthest from the wellbore). Often, a portion of the fracture may be hydraulically isolated, or "cut-off" so that the hydrocarbon flowing from the formation into the fracture completely bypasses this tip region, as shown in FIG. 2. Ground level is shown at S. The direction of hydrocarbon flow is shown at 38. Thus hydrocarbon flows--aided by the presence of the newly created fracture from the formation 40 into the fracture 42--traverses the fracture until it gets to wellbore 10 where it is recovered at the surface. A similar flowpath is shown at 44. These flowpaths can define two regions 46, a producing region, and 48, a nonproducing region at the fracture tip that is isolated from the rest of the fracture since no hydrocarbon flows through this portion of the fracture, thus no pressure gradient exists. This phenomenon (in addition to others) ensures that the stagnant fracture fluid will remain in the fracture tip rather than being displaced by producing hydrocarbon, which can occur in the region shown at 46.
Generally speaking, creating a fracture in a hydrocarbon-bearing formation requires a complex suite of materials. In the case of conventional fracture treatments, five crucial components are required: a carrier fluid (usually water or brine), a polymer, a cross-linker, a proppant, and a breaker. (Numerous other components are sometimes added, e.g. fluid loss agents, whose purpose is to control leak-off, or migration of the fluid into the fracture face.) The first three component are injected first, and actually creates/extends the fracture. Roughly, the purpose of these fluids is to first create/extend the fracture, then once it is opened sufficiently, to deliver proppant into the fracture, which keeps the fracture from closing once the pumping operation is completed. The carrier fluid is simply the means by which the proppant and breaker (breaker can also be added to the fluid used to create/extend the fracture and commonly is) are carried into the formation. Thus, the fracturing fluid is typically prepared by blending a polymeric gelling agent with an aqueous solution (sometimes oil-based, sometimes a multi-phase fluid is desirable); often, the polymeric gelling agent is a solvatable polysaccharide, e.g., galactomannan gums, glycomannan gums, and cellulose derivatives. The purpose of the solvatable (or hydratable) polysaccharides is: (1) to provide viscosity to the fluid so that in can create/extend the fracture; and (2) to thicken the aqueous solution so that solid particles known as "proppant" (discussed below) can be suspended in the solution for delivery into the fracture. Again, the purpsoe of the proppant is to literally hold open or prop open the fracture after it has been created. Thus the polysaccharides function as viscosifiers, that is, they increase the viscosity of the aqueous solution by 10 to 100 times, or even more. In many fracturing treatments, a cross-linking agent is added which further increases the viscosity of the solution by cross-linking the polymer. The borate ion has been used extensively as a crosslinking agent for hydrated guar gums and other galactomannans to form aqueous gels, e.g., U.S. Pat. No. 3,059,909. Other demonstrably suitable cross-linking agents include: titanium (U.S. Pat. No. 3,888,312), chromium, iron, aluminum and zirconium (U.S. Pat. No. 3,301,723).
The purpose of the proppant is to keep the newly fractured formation in that fractured state, i.e., from re-closing after the fracturing process is completed; thus, it is designed to keep the fracture open--in other words to provide a permeable path (along the fracrture) for the hydrocarbon to flow through the fracture and into the wellbore. More specifically, the proppant provides channels within the fracture through which the hydrocarbon can flow into the wellbore and therefore be withdrawn or "produced." Typical material from which the proppant is made includes sand (e.g. 20-40 mesh), bauxite, man-made intermediate-strength materials and glass beads. The proppant can also be coated with resin (which causes the resin particles to stick to one another) to help prevent proppant flowback in certain applications. Thus, the purpose of the fracturing fluid generally is two-fold: (1) to create or extend an existing fracture through high-pressure introduction into the geologic formation of interest; and (2) to simultaneously deliver the proppant into the fracture void space so that the proppant can create a permanent channel through which the hydrocarbon can flow to the wellbore. Once this second step has been completed, it is desirable to remove the fracturing fluid (minus the proppant) from the fracture--its presence in the fracture is deleterious, since it plugs the fracture and therefore impedes the flow hydrocarbon. This effect is naturally greater in high permeability formations, since the fluid can readily fill the (larger) void spaces. This contamination of the fracture by the fluid is referred to as decreasing the effective fracture length. And the process of removing the fluid from the fracture once the proppant has been delivered is referred to as "fracture clean-up." For this, the final component of the fracture fluid becomes relevant: the breaker. The purpose of the breaker is to lower the viscosity of the fluid so that it is more easily removed fracture. Nevertheless, no completely satisfactory method exists to recover the fluid, and therefore prevent it from reducing the effective fracture length. Again, fluid recovery after delivering the proppant to the fracture represents one of the major technological dilemmas in the oilfield services field. The instant Invention is directed primarily to methods for recovering the fracturing fluid once the fluid has successfully delivered the proppant to the fracture.
Diminished effective fracture length (EFL) caused by fracture fluid retention in the fracture is an empirically demonstrable problem that results in substantially reduced well yields. The EFL can be calculated by production decline and pressure transient analysis; values obtained this way can then be compared with the true fracture length obtained using standard geometry models. EFL values of about one-half of the actual fracture length are common.
Essentially, techniques for fracture clean-up, which again, refers to recovering the proppant-less fluid from the fracture, often involves reducing the fluid's viscosity as much as practicable so that it more readily flows back towards the wellbore. Again, the goal is to recover as much fluid as possible, since fluid left in the fracture reduces the effective fracture length. Among the most troublesome aspect of fluid recovery, or clean-up is recovering that portion of the fluid at the very tip of the fracture.
The methods for fracture fluid clean-up taught in the prior art all involve removing the fracturing fluid through the same route by which the fluid was introduced into the fracture--i.e., by flowing or pumping the fluid back through the wellbore then to the surface where it is removed. The disadvantages of this method are obvious. For one thing, the fluid must traverse the entire length of the fracture--a distance often over 1000 feet in low permeability formations. Moreover, clean-up this way is expensive and time-consuming, and rarely results in effective clean-up, i.e., fluid often remains in the fracture tip, thus decreasing the effective fracture length. Indeed the time-honored empirical observation is that the effective fracture length is about 50 to 60% of the fracture length--after clean-up. The method of the present Invention is directed to a method of fluid removal not involving traversal of the fracture length and up the wellbore. Instead, the fluid is removed according to the present Invention by inducing fluid flow into the fracture faces or orthogonal to the conventional flowpath.
Although the system of the present Invention is novel in the art, others have disclosed the movement of fluids in subsurface environments by other non-hydraulic means, though not in a fracturing context. Eric van Oort, et al. at Shell in a series of SPE papers and U.S. Pat. No. 5,686,396, have investigated the problem of shale destabilization during drilling. E.g.: Eric van Oort, et al., Physico-Chemical Stabilization of Shales, SPE 37263; and Eric van Oort, et al., Manipulation of Coupled Osmotic Flows for Stabilization of Shales Exposed to Water-Based Drilling Fluids, SPE 30499. Jay P. Simpson, Studies of the Effects of Drilling Fluid/Shale Interactions on Borehole Instability, GasTIPS, 30, Spring 1997.
These authors/inventors posit that the economically devastating problem of shale instability--which is responsible for, among other things, stuck pipe due to well caving and collapse, cementing failures, and lost circulation--is caused by migration of low-solute fluid (i.e., the drilling fluid or "mud") into the surrounding shale. This movement occurs in response to a chemical potential gradient--i.e., the solvent in low-solute fluid moves to the high-solute fluid contained in the shale pore spaces. The result is that the shale surrounding the borehole can take up/absorb drilling fluid until it literally bursts--i.e., the outward stress exerted by the imbedded fluid overcomes the shale's intrinsic strength--with consequent problems for the contiguous wellbore. This unusual behavior of shale is a direct consequence of its ability to behave as a selectively permeable membrane (i.e., selectively permeable to water in preference to solutes).
U. S. Pat. No. 5,686,396 discloses a method for improving the osmotic efficiency of shale during the drilling process. More specifically, the method involves adding compositions to the drilling fluid so that the solute content of the drilling fluid more nearly matches that of the contiguous shale system. This way, the invasion of drilling fluid into the surrounding shale system is minimized. Again, the essential physico-chemical concepts relied upon by the inventors of the '396 patent are related to those relied upon in the present Invention; nevertheless, the application (drilling versus stimulation) and actual problem to be solved (keeping fluid out of the shale versus deliberately directing fluid into the shale) are drastically different. Therefore, the van Oort references, including the '396 patent, are directed to a different problem in an entirely different setting. Finally, the van Oort references only disclose (or suggest) exploiting indigenous membrane systems--none of these references teaches deliberately creating a capillary pressure gradient in the subsurface. The present Invention is directed in part to the creation of such systems.
More particularly, the phenomenon of capillary imbibition has been intensively studied by reservoir scientists to better understand hydrocarbon movement in the subsurface. See, e.g., C. J. Radke, et al., A Pore-Level Scenario for the Development of Mixed Wettability in Oil Reservoirs, SPE 24880. The physico-chemical principles that underlie the phenomenon is described for instance, in, R. Lenormand, et al., Modeling the Diffusion Flux Between Matrix and Fissure in a Fissured Reservoir, SPE 49007; and, C. Murat, et al., An Examination of Countercurrent Capillary Imbibition Recovery from Single Matrix Blocks and Recovery Predictions by Analytical Matrix/Fracture Transfer Functions, SPE 49005; both of these papers are hereby incorporated by reference in their entirety into the present Application, and in particular those portions of the papers discussing the general phenomenon of capillary imbibition. The concept of relative permeability also been applied to stimulation--the domain to which the present Invention is directed--though in a substantially different application, namely conformance control. Dalrymple, et al. in Results of Using a Relative-Permeability Modifier with a Fracture-Stimulation Treatment, SPE 49043, investigated a novel relative permeability modifier--actually generated in situ--to seal off zones from water intrusion while still permitting hydrocarbon flow (i.e., a disproportionate permeability reduction). The authors state that the mechanism by which the permeability modifier operates is based on lining the pore-throat regions, thereby acting as a brush or micro-valve, permitting hydrocarbon intrusion but not water movement. The Dalrymple paper is not directed to removing spent fracturing fluid (clean-up) but rather to conformance control.